EX-99.1 2 exh99_1.htm EXHIBIT 99.1
Exhibit 99.1



CRESCENT POINT ENERGY CORP.
ANNUAL INFORMATION FORM
For the Year Ended December 31, 2015
Dated March 8, 2016

 
TABLE OF CONTENTS
 
SPECIAL NOTES TO READER
    
1
  
GLOSSARY
    
4
  
SELECTED ABBREVIATIONS
    
6
  
CURRENCY OF INFORMATION
    
7
  
OUR ORGANIZATIONAL STRUCTURE
    
7
  
GENERAL DEVELOPMENT OF THE BUSINESS OF THE CORPORATION
    
9
  
DESCRIPTION OF OUR BUSINESS
    
11
  
STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION
    
16
  
ADDITIONAL INFORMATION RESPECTING CRESCENT POINT
    
40
  
INDUSTRY CONDITIONS
    
50
  
RISK FACTORS
    
64
  
DIVIDENDS
    
79
  
MARKET FOR SECURITIES
    
80
  
CONFLICTS OF INTEREST
    
81
  
LEGAL PROCEEDINGS
    
81
  
AUDIT COMMITTEE
    
81
  
TRANSFER AGENT AND REGISTRARS
    
83
  
MATERIAL CONTRACTS
    
83
  
INTERESTS OF EXPERTS
    
84
  
ADDITIONAL INFORMATION
    
84
  

APPENDIX A                                   -     AUDIT COMMITTEE TERMS OF REFERENCE
APPENDIX B                                   -     RESERVES COMMITTEE TERMS OF REFERENCE
APPENDIX C                                   -     REPORTS ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR
APPENDIX D                                   -     REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION


SPECIAL NOTES TO READER
Any "financial outlook" or "future oriented financial information" in this annual information form, as defined by applicable securities legislation has been approved by management of Crescent Point (as defined herein). Such financial outlook or future oriented financial information is provided for the purpose of providing information about management's current expectations and plans relating to the future. Readers are cautioned that reliance on such information may not be appropriate for other purposes.
This annual information form and other reports and filings made with the securities regulatory authorities include certain statements that constitute "forward-looking statements" within the meaning of section 27A of the Securities Act of 1933, section 21E of the Securities Exchange Act of 1934 and the United States Private Securities Litigation Reform Act of 1995 and "forward-looking information" for the purposes of Canadian securities regulation (collectively, "forward-looking statements"). All forward-looking statements are based on our beliefs and assumptions based on information available at the time the assumption was made. Crescent Point has tried to identify such forward-looking statements by use of such words as "could", "should", "can", "anticipate", "expect", "believe", "will", "may", "intend", "projected", "sustain", "continues", "strategy", "potential", "projects", "grow", "take advantage", "estimate", "well-positioned" and similar expressions, but these words are not the exclusive means of identifying such statements. These forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. Crescent Point believes the expectations reflected in those forward-looking statements are reasonable but no assurance can be given that these expectations will prove to be correct and such forward-looking statements should not be unduly relied upon. These statements speak only as of the date of this AIF or, if applicable, as of the date specified in this AIF.
In particular, this AIF contains forward-looking statements pertaining, among other things, to the following:
· corporate strategy and anticipated financial and operational performance;
· business prospects;
· the performance characteristics of Crescent Point's oil and natural gas properties, including but not limited to oil and natural gas production levels;
· anticipated future cash flows and oil and natural gas production levels;
· projected returns and exploration potential of our assets;
· the potential of Crescent Point's plays;
· future development plans;
· capital expenditure programs and how they will be funded;
· corporate and asset acquisition opportunities;
· drilling programs;
· expected cost savings and efficiencies;
· the future cost to drill wells, including anticipated cost savings associated therewith;
· the quantity of the oil and natural gas reserves;
· projections of commodity prices and costs;
· our future waterflood programs;
· the impact of the use of closable sliding sleeve completion technology;
· ongoing efforts to reduce or eliminate fresh water usage in Viewfield Bakken and Shaunavon completions;
· future downspacing;
· expected decommissioning, abandonment, remediation and reclamation costs;
· our tax horizon;
· expected trends in environmental regulation;
· payment of monthly dividends;
· supply and demand for oil and natural gas;
· expectations regarding the ability to raise capital and to continually add to reserves through acquisitions and development; and
· treatment under governmental regulatory regimes.
By their nature, such forward-looking statements are subject to a number of risks, uncertainties and assumptions, which could cause actual results or other expectations to differ materially from those anticipated, expressed or implied by such statements, including those material risks discussed in our Management's Discussion and Analysis for the year ended December 31, 2015, under the headings "Risk Factors" and "Forward-Looking Information". The material assumptions and factors in making forward-looking statement are disclosed in the Management's Discussion and Analysis for the year ended December 31, 2015, under the headings "Marketing and Prices", "Dividends", "Capital Expenditures", "Decommissioning Liability", "Liquidity and Capital Resources", "Risk Factors", "Critical Accounting Estimates", "Changes in Accounting Policies" and "Outlook".
This information contains certain forward-looking estimates that involve substantial known and unknown risks and uncertainties, certain of which are beyond Crescent Point's control. Such risks and uncertainties include, but are not limited to: financial risk of marketing reserves at an acceptable price given market conditions; volatility in market prices for oil and natural gas; delays in business operations, pipeline restrictions, blowouts; the risk of carrying out operations with minimal environmental impact; industry conditions including changes in laws and regulations and the adoption of new environmental laws and regulations and changes in how they are interpreted and enforced; uncertainties associated with estimating oil and natural gas reserves; risks and uncertainties related to oil and gas interests and operations on tribal lands; economic risk of finding and producing reserves at a reasonable cost; uncertainties associated with partner plans and approvals; operational matters related to non-operated properties; increased competition for, among other things, capital, acquisitions of reserves and undeveloped lands; competition for and availability of qualified personnel or management; incorrect assessments of the value of acquisitions and exploration and development programs; unexpected geological, technical, drilling, construction and processing problems; availability of insurance; fluctuations in foreign exchange and interest rates; stock market volatility; failure to realize the anticipated benefits of acquisitions; general economic, market and business conditions; uncertainties associated with regulatory approvals; uncertainty of government policy changes; uncertainties associated with credit facilities and counterparty credit risk; changes in income tax laws, tax laws, crown royalty rates and incentive programs relating to the oil and gas industry; and other factors, many of which are outside the control of Crescent Point. The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as each of these are interdependent and Crescent Point's future course of action depends on management's assessment of all information available at the relevant time.
Statements relating to "reserves" and "resources" are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future. Actual reserve values may be greater than or less than the estimates provided herein.
There are numerous uncertainties inherent in estimating quantities of crude oil, natural gas and natural gas liquids reserves and the future cash flows attributed to such reserves. The reserve and associated cash flow information set forth herein are estimates only. In general, estimates of economically recoverable crude oil, natural gas and natural gas liquids reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil and natural gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially. For these reasons, estimates of the economically recoverable crude oil, natural gas liquids and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues associated with reserves prepared by different engineers, or by the same engineers at different times, may vary. Crescent Point's actual production, revenues, taxes and development and operating expenditures with respect to its reserves will vary from estimates thereof and such variations could be material. In addition, the discounted and undiscounted net present value of future net revenues attributable to reserves do not represent fair market value; and the estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation. Therefore, Crescent Point's actual results, performance or achievements could differ materially from those expressed in, or implied by, these forward-looking estimates and if such actual results, performance or achievements transpire or occur, or if any of them do so, there can be no certainty as to what benefits Crescent Point will derive therefrom.
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Barrels of oil equivalent ("boe") may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf: 1 Bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
The aggregate of the exploration and development costs incurred in the most recent financial year and the change during the year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for the year.
Additional information on these and other factors that could affect Crescent Point's operations or financial results are included in Crescent Point's reports on file with Canadian and U.S. securities regulatory authorities (including our Annual Information Form, Annual Report on Form 40-F and Management's Discussion and Analysis). Readers are cautioned not to place undue reliance on the forward-looking information, which is given as of the date it is expressed in this AIF or otherwise. We do not undertake any obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as required pursuant to applicable securities laws. All subsequent forward-looking statements, whether written or oral, attributable to Crescent Point or persons acting on the Company's behalf are expressly qualified in their entirety by these cautionary statements.
Presentation of our Reserve and Resource Information
Current SEC reporting requirements permit oil and gas companies to disclose Probable reserves (as defined herein), in addition to the required disclosure of Proved Reserves. Under current SEC requirements, net quantities of reserves are required to be disclosed, which requires disclosure on an after royalties basis and does not include reserves relating to the interests of others. For a description of these and additional differences between Canadian and US standards of reporting reserves, see "Risk Factors — Canadian and United States practices differ in reporting reserves and production and our estimates may not be comparable to those of companies in the United States".
New York Stock Exchange
As a Canadian corporation listed on the NYSE, we are not required to comply with most of the NYSE's corporate governance standards and, instead, may comply with Canadian corporate governance practices. We are, however, required to disclose the significant differences between our corporate governance practices and the requirements applicable to U.S. domestic companies listed on the NYSE. Except as summarized on our website at www.crescentpointenergy.com, we are in compliance with the NYSE corporate governance standards in all significant respects.
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GLOSSARY
In this AIF, the capitalized terms set forth below have the following meanings:
"ABCA" means the Business Corporations Act, R.S.A. 2000, c. B-9, as amended, including the regulations promulgated thereunder.
"AIF" means this annual information form of the Corporation dated March 8, 2016 for the year ended December 31, 2015.
"CanEra" means CanEra Energy Corp.
"CanEra Arrangement" means the plan of arrangement under Section 193 of the ABCA involving CanEra and the Corporation, completed on May 15, 2014, as more particularly described under the heading "General Development of the Business of the Corporation – History – 2014".
"Common Shares" means common shares in the capital of the Corporation.
"Conversion Arrangement" means the plan of arrangement under Section 193 of the ABCA, completed on July 2, 2009 pursuant to which the Trust effectively converted from an income trust to a corporate structure.
"Coral Hill" means Coral Hill Energy Ltd.
"Coral Hill Arrangement" means the plan of arrangement under Section 193 of the ABCA involving Coral Hill and the Corporation, completed on August 14, 2015, as more particularly described under the heading "General Development of the Business of the Corporation – History – 2015".
"CPEUS" means Crescent Point Energy U.S. Corp.
"CPHI" means Crescent Point Holdings Inc.
"CPLux" means Crescent Point Energy Lux S.à r.l.
"CPUSH" means Crescent Point U.S. Holdings Corp.
"Crescent Point" or the "Corporation" means Crescent Point Energy Corp., formerly Wild River Resources Ltd., a corporation amalgamated under the ABCA and, where applicable, includes its subsidiaries and affiliates.
"DRIP" means the Premium DividendTM and Dividend Reinvestment Plan of the Corporation.
"DSU Plan" means the Deferred Share Unit Plan of the Corporation.
"GLJ" means GLJ Petroleum Consultants Ltd.
"Greenhouse Gases" or "GHGs" means any or all of carbon dioxide (CO2), methane (CH4), nitrous oxide (N2O), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and sulphur hexafluoride (SF6).
"IFRS" means International Financial Reporting Standards as adopted by the Canadian Accounting Standards Board for periods beginning on and after January 1, 2011.
"Legacy" means Legacy Oil + Gas Inc.
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"Legacy Arrangement" means the plan of arrangement under Section 193 of the ABCA involving Legacy and the Corporation, completed on June 30, 2015, as more particularly described under the heading "General Development of the Business of the Corporation – History – 2015".
"MD&A" means the management's discussion and analysis of financial condition and results of operations of the Corporation for the year ended December 31, 2015.
"NI 51-101" means "National Instrument 51-101 – Standards for Disclosure for Oil and Gas Activities".
"NYSE" means the New York Stock Exchange.
"OPEC" means Organization of the Petroleum Exporting Countries.
"Partnership" means Crescent Point Resources Partnership, a general partnership formed under the laws of the Province of Alberta, having CPHI and the Corporation as partners.
"Restricted Share Bonus Plan" means the Restricted Share Bonus Plan of the Corporation.
"SDP" means the Share Dividend Plan of the Corporation.
"SEC" means the U.S. Securities and Exchange Commission.
"Shareholders" means the holders from time to time of Common Shares.
"Shelter Bay" means Shelter Bay Energy Inc.
"Sproule" means Sproule Associates Limited.
"T. Bird" means T. Bird Oil Ltd.
"Tax Act" means the Income Tax Act (Canada), R.S.C. 1985, c. 1 (5th Supp.), and the regulations promulgated thereunder, each as amended from time to time.
"Trust" means Crescent Point Energy Trust, an unincorporated open ended investment trust governed by the laws of the Province of Alberta that was dissolved pursuant to the Conversion Arrangement.
"Trust Units" means the trust units of the Trust.
"TSX" means the Toronto Stock Exchange.
"Unitholders" means holders of Trust Units.
"U.S." means the United States of America.
"Viking Assets" means the assets located in the Viking play at Dodsland, Saskatchewan, acquired from Polar Star Canadian Oil and Gas Inc.
"Wild Stream" means Wild Stream Exploration Ltd.
"Wild Stream Arrangement" means the plan of arrangement under Section 193 of the ABCA involving Wild Stream and the Corporation, completed on March 15, 2012.
In this AIF, references to "dollars" and "$" are to the currency of Canada, unless otherwise indicated.
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SELECTED ABBREVIATIONS
In this AIF, the abbreviations set forth below have the following meanings:
 
Oil and Natural Gas Liquids
 
 
Natural Gas
 
bbl
Barrel
Mcf
thousand cubic feet
bbls
Barrels
Mcf/d
thousand cubic feet per day
bbl/d
Mbbls
NGLs
barrels per day
thousand barrels
natural gas liquids
Mcfe
thousand cubic feet of gas equivalent converting one barrel of oil to 6 Mcf of natural gas equivalent
 
MMcf
MMcf/d
million cubic feet
million cubic feet per day
MMBTU
million British Thermal Units
GJ
gigajoule

Other
 
  
AECO
 
the natural gas storage facility located at Suffield, Alberta
 
boe
 
barrel of oil equivalent of natural gas and crude oil on the basis of 1 boe for 6 (unless otherwise stated) Mcf of natural gas (this conversion factor is an industry accepted norm and is not based on either energy content or current prices)
 
boe/d
 
barrel of oil equivalent per day
 
m³
 
cubic metres
 
M$
 
thousand dollars
 
Mboe
 
thousand barrels of oil equivalent
 
MMboe
 
million barrels of oil equivalent
 
MM$
 
million dollars
 
MW
 
megawatt
 
MW/h
 
megawatt per hour
 
WTI
 
West Texas Intermediate, the reference price paid in U.S. dollars at Cushing, Oklahoma for crude oil of standard grade
 

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CURRENCY OF INFORMATION
The information set out in this AIF is stated as at December 31, 2015 unless otherwise indicated. Capitalized terms used but not defined in the text are defined in the Glossary.
OUR ORGANIZATIONAL STRUCTURE
The Corporation
Crescent Point Energy Corp. (the "Corporation" and, together with its direct and indirect subsidiaries and partnerships, where appropriate, "we", "our" or "us") is the successor to the Trust, following the completion of the "conversion" of the Trust from an income trust to a corporate structure under the Conversion Arrangement. Pursuant to the Conversion Arrangement, Unitholders of the Trust exchanged their Trust Units for Common Shares of the Corporation on a one-for-one basis.
The Corporation was originally incorporated pursuant to the provisions of the Company Act (British Columbia) on April 20, 1994 as 471253 British Columbia Ltd. 471253 British Columbia Ltd. changed its name to Westport Research Inc. ("Westport") on August 12, 1994. On August 1, 2006, Westport was continued into Alberta under the ABCA. On October 11, 2006, Westport changed its name to 1259126 Alberta Ltd. ("1259126"). On February 8, 2007, 1259126 amended its articles to change its name to Wild River Resources Ltd. ("Wild River"), to add a class of non-voting common shares, to change the number of authorized Common Shares from 1,000,000 to unlimited and to change the rights, privileges, restrictions and conditions attaching to such shares, to reorganize its share structure, to change the number of Wild River's issued and outstanding shares on a pro rata basis to an aggregate of 5,000,000 Common Shares, to remove the restrictions on share transfer and to amend the "other provisions" section of the articles. On June 29, 2009, Wild River amended its articles to cancel the non-voting common shares and to change the rights, privileges, restrictions and conditions of the Common Shares to remove the references to the non-voting common shares. On July 2, 2009, in connection with the Conversion Arrangement, Wild River filed Articles of Amendment to give effect to the consolidation of the Common Shares on the basis of 0.1512 of a post-consolidation Common Share for each pre-consolidation Common Share and subsequent Articles of Amendment to change its name to Crescent Point Energy Corp. On January 1, 2011, the Corporation amalgamated with Ryland Oil ULC, Darian Resources Ltd. and Shelter Bay Energy ULC.
The head and principal office of the Corporation is located at Suite 2000, 585 – 8th Avenue S.W., Calgary, Alberta, T2P 1G1 and its registered office is located at Suite 3700, 400 – 3rd Avenue S.W., Calgary, Alberta, T2P 4H2.
The Corporation is a conventional oil and gas producer with assets strategically focused in properties comprised of high quality, long life, operated, light and medium oil and natural gas reserves in Western Canada and the United States.
We make monthly cash dividends to Shareholders from our net cash flow. Our primary source of cash flow is distributions from the Partnership.
Partnership
The Partnership is a general partnership governed by the laws of the Province of Alberta. As set forth in the diagram below under "Organizational Structure of the Corporation", the partners of the Partnership are CPHI and the Corporation.
The existing business of the Corporation is carried on through the Partnership and through CPEUS. The Partnership holds all of the Corporation's Canadian operating assets and CPEUS holds all of the Corporation's U.S. operating assets.
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CPHI
CPHI is a wholly-owned subsidiary of the Corporation. CPHI is a partner of the Partnership.
CPLux
CPLux is a wholly-owned indirect subsidiary of the Corporation.
CPUSH
Crescent Point U.S. Holdings Corp. is a wholly-owned direct subsidiary of the Corporation.
CPEUS
Crescent Point Energy U.S. Corp. is a wholly-owned indirect subsidiary of the Corporation. CPEUS holds the Corporation's operating assets in the United States.
Relationships
The following table provides the name, the percentage of voting securities owned by the Corporation and the jurisdiction of incorporation, continuance or formation of the Corporation's material subsidiaries as at the date hereof.
 
 
 
Percentage of Voting Securities (Directly or Indirectly)
 
 
  
 
 
Jurisdiction of Incorporation/Formation
 
 
CPHI
100%
  
Alberta
Partnership
100%
  
Alberta
CPUSH
100%
  
Nevada
CPEUS
100%
  
Delaware
CPLux
100%
  
Luxembourg

 
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Organizational Structure of the Corporation
The following diagram describes the intercorporate relationships among the Corporation and its material direct and indirect subsidiaries described above as at March 8, 2016. Reference should be made to the appropriate sections of this AIF for a complete description of the structure of the Corporation.
GENERAL DEVELOPMENT OF THE BUSINESS OF THE CORPORATION
History
The following is a description of the general development of the business of Crescent Point over the past three years.
2013
On April 25, 2013, the Corporation announced that its board of directors approved the adoption of an advanced notice by-law, which requires advance notice to the Corporation in circumstances where nominations of persons for election as a director of the Corporation are made by Shareholders other than pursuant to: (i) a requisition of a meeting made pursuant to the provisions of the ABCA; or (ii) a shareholder proposal made pursuant to the provisions of the ABCA.
On June 12, 2013, the Corporation closed an offering of senior guaranteed notes in the United States and Canada on a private placement basis with aggregate principal amounts of US$290 million and $10 million. The terms of the U.S. notes range from 5 to 10 years with a weighted average term of 9.7 years and coupon rates ranging from 2.65% to 3.78% and the terms of the Canadian note are 10 years with a coupon rate of 4.11%.
On July 17, 2013, the Corporation renewed and extended the term of the Syndicated Credit Facility by 1 year to June 10, 2016.
On October 15, 2013, the Corporation announced the suspension of the premium component of its DRIP effective with the October 2013 dividend which was paid on November 15, 2013. Effective with the suspension, Shareholders previously enrolled in the premium component of the DRIP received the regular cash dividend amount of $0.23 per share without the two percent premium.
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2014
On January 22, 2014, the Common Shares began trading on the NYSE under the symbol "CPG".
On March 17, 2014, Robert Heinemann was appointed as a director of the Corporation.
On May 9, 2014, the Corporation adopted the SDP. See "Share Dividend Plan".
On May 15, 2014, the Corporation closed the CanEra Arrangement for total consideration of approximately $1.1 billion, comprised of 12,928,091 Crescent Point Common Shares, cash consideration of approximately $191.8 million and assumed debt. See "Description of Our Business – Reorganizations".
On June 12, 2014, the Corporation completed the acquisition of the Viking Assets in Saskatchewan for total consideration of approximately $331.7 million comprised of approximately 7.6 million Crescent Point Common Shares less net cash received on customary closing adjustments of $12.0 million.
On June 24, 2014, the Corporation closed an offering of senior guaranteed notes in the United States and Canada on a private placement basis in aggregate principal amounts of US$310 million and $40 million. The terms of the U.S. notes range from 7 to 10 years with a weighted average term of 9.5 years and coupon rates ranging from 3.29% to 3.75% and the terms of the Canadian note are 10 years with a coupon rate of 3.85%.
On July 30, 2014, the Corporation completed the acquisition of certain assets in the Viewfield Bakken and Flat Lake resource plays in southeast Saskatchewan for cash consideration of $99.1 million.
On August 12, 2014, the total amount available under the Corporation's syndicated credit facility and operating credit facility was increased to a total of $2.6 billion and the term was extended to June 10, 2017.
On August 13, 2014, the Corporation closed the acquisition of all issued and outstanding common shares of T. Bird, a private oil and gas company with properties in southeast Saskatchewan and Manitoba. Total consideration was approximately $85.7 million, comprised of 1,482,477 Crescent Point Common Shares, cash consideration of $0.3 million and assumed debt.
On September 23, 2014, the Corporation completed an equity offering of 18,435,000 Common Shares at $43.40 per Common Share for aggregate gross proceeds of approximately $800 million.
On September 30, 2014, the Corporation completed the acquisition of approximately 3,300 boe/d of conventional oil production and 76 net sections of land that are contiguous to Crescent Point's existing land base in southeast Saskatchewan and Manitoba. Total consideration for the assets included certain Crescent Point assets in Creelman, Saskatchewan and net cash consideration of $374.3 million.
On November 4, 2014, Laura Cillis was appointed as a director of the Corporation.
On November 4, 2014, the Corporation announced the passing of Ken Cugnet.  Mr. Cugnet served as a director of the Corporation since 2003.
2015
On March 10, 2015, the total amount available under the Corporation's syndicated credit facility and operating credit facility was increased to a total of $3.6 billion and the term was extended to June 8, 2018.
On April 22, 2015, the Corporation closed an offering of senior guaranteed notes in the United States and Canada on a private placement basis in aggregate principal amounts of US$250.0 million and $65.0 million. The terms of the U.S. notes range from 10 to 12 years with a weighted average term of 10.2 years and coupon rates ranging from 4.08% to 4.18% and the terms of the Canadian notes are 10 years with a coupon rate of 3.94%.
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On June 16, 2015, the Corporation completed an equity offering of 23,160,000 Common Shares at $28.50 per Common Share for aggregate gross proceeds of approximately $660 million.
On June 30, 2015, the Corporation closed the Legacy Arrangement for total consideration of approximately $1.5 billion, comprised of 18,229,428 Crescent Point Common Shares, cash consideration of $19.4 million and assumed debt. See "Description of Our Business – Reorganizations".
On July 20, 2015, the Corporation filed a short form base shelf prospectus for an aggregate offering amount not to exceed $2.5 billion. The prospectus allows Crescent Point to offer and issue common shares, subscription receipts, warrants, options and debt securities in Canada and the U.S. at any time during the 25-month period that the prospectus remains in place. As of March 8, 2016, no offerings have been made pursuant to the shelf prospectus.
On August 12, 2015, the Corporation reduced its monthly dividend to $0.10 per share, effective with the August dividend payable on September 15, 2015. In addition, effective with the August dividend, the Corporation suspended the SDP and DRIP.  See "Additional Information Respecting Crescent Point – Share Dividend Plan".
On August 14, 2015, the Corporation closed the Coral Hill Arrangement pursuant to which the Corporation acquired all of the remaining issued and outstanding shares of Coral Hill not already owned by the Corporation (as at August 14, 2015, Crescent Point had an 8.7% equity interest in Coral Hill) for total consideration of $243.8 million, comprised of 4,283,680 Crescent Point Common Shares, assumed debt and the historical cost of Crescent Point's previously held equity investment of $42.0 million. See "Description of Our Business – Reorganizations".
On November 5, 2015, Gregory T. Tisdale announced that effective December 31, 2015, he was stepping down from his role as Chief Financial Officer of the Corporation. Ken Lamont, then Crescent Point's Vice President, Finance and Treasurer, was appointed Chief Financial Officer effective January 1, 2016.
On November 5, 2015, it was announced that Mark Eade was appointed as Vice President, General Counsel and Corporate Secretary effective September 1, 2015.
2016
On March 8, 2016, Barbara Munroe was appointed as a director of the Corporation. See "Additional Information Respecting Crescent Point – Directors and Officers".
On March 8, 2016, the Corporation reduced its monthly dividend to $0.03 per share, effective with the March dividend payable on April 15, 2016.
DESCRIPTION OF OUR BUSINESS
General
The Corporation is an oil and gas exploration, development and production company. The Corporation is a conventional oil and gas producer with assets strategically focused in properties comprised of high quality, long life, operated, light and medium oil and natural gas reserves in Western Canada and the United States. The primary assets of the Corporation are currently its interest in the Partnership, shares in CPHI, and shares in CPUSH and, indirectly, shares in CPEUS.
The crude oil and natural gas properties and related assets generating income for the benefit of the Corporation are located in the provinces of Saskatchewan, Alberta, British Columbia and Manitoba and the states of North Dakota, Montana, Colorado and Utah. The properties and assets consist of producing crude oil and natural gas reserves and Proved plus Probable (as defined herein) crude oil and natural gas reserves not yet on production and land.
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We pay monthly cash dividends to Shareholders from our net cash flow in accordance with our dividend policy. Our primary sources of cash flow are distributions from the Partnership. See "Dividends".
Strategy
We strive to create sustainable, value-added growth in reserves, production and cash flow through the execution of management's integrated strategy of acquiring, exploiting and developing high quality, long life, light and medium oil and natural gas properties.
We continually investigate and search out producing properties including those with large resource potential that we believe will result in meaningful reserve and production additions. We generally focus capital on higher-quality, longer-life reservoirs in proven growth areas that offer existing infrastructure, low cost drilling and multi-zone potential. Our goal is to acquire operational control of properties that we believe offer significant exploitation and development potential.
We develop our properties through a detailed technical analysis of information including reservoir characteristics, petroleum initially in place, recovery factors and the applicability of enhanced recovery techniques. Our goal is to increase reserves and production in a cost effective manner through a number of techniques, including drilling infill and step-out wells, fracture stimulation of horizontal wells, re-completing existing wells and implementing waterflood or pressure support schemes.
Risk Management and Marketing
Factors outside our control impact, to varying degrees, the prices we receive for production and the associated operating expenses we incur. These include but are not limited to:
(a) world market forces, including world supply and consumption levels and the ability of the OPEC to set and maintain production levels and prices for crude oil;
(b) political conditions, including the risk of hostilities in the Middle East and other regions throughout the world;
(c) increases or decreases in crude oil differentials and their implications for prices received by us;
(d) the impact of changes in the exchange rate between Canadian and U.S. dollars on prices received by us for our crude oil and natural gas;
(e) North American market forces, most notably shifts in the balance between supply and demand for crude oil and natural gas and the implications for the prices of crude oil and natural gas;
(f) availability, proximity and capacity of oil and gas gathering systems, pipeline and processing facilities, railcars and railcar loading facilities;
(g) global and domestic economic and weather conditions;
(h) price and availability of alternative fuels; and
(i) the effect of energy conservation measures and government regulations.
Fluctuations in commodity prices, differentials and foreign exchange and interest rates, among other factors, are outside of our control and yet can have a significant impact on the level of cash we have available for payment of dividends to Shareholders.
To mitigate a portion of these risks, we actively initiate, manage and disclose the effects of our hedging activities. Our strategy for crude oil and natural gas production is to hedge up to 65%, or as otherwise approved by the board of directors, of our existing net of royalty production on a rolling three and a half year basis, at the discretion of management. With recent increases in the volatility of price differentials between WTI and western Canadian crude prices, Crescent Point has expanded its risk management programs to include the hedging of these differentials. The Corporation uses a combination of financial derivatives and fixed-differential physical contracts to hedge these price differentials. For differential hedging, Crescent Point's risk management program allows for hedging a forward profile of 3½ years, and up to 35% net of royalty production. All hedging activities are governed by our Risk Management and Counterparty Credit Policy and are regularly reviewed by the board of directors.
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As part of our risk management program, benchmark oil prices are hedged using financial WTI-based instruments transacted in Canadian dollars and benchmark natural gas prices are hedged using financial AECO-based instruments transacted in Canadian dollars. Total financial oil and gas hedges in 2015 amounted to approximately 51% of annual production, net of royalties, consisting of approximately 52% of annual liquids production and approximately 37% of annual natural gas production, net of royalties. The primary objective of this strategy is to be well positioned to maximize shareholder return with long-term growth plus dividend income. The Corporation recorded a realized derivative gain on oil and gas hedge contracts of $642.6 million in 2015.
The following table summarizes our commitments under all hedging agreements as at December 31, 2015.
Financial WTI Crude Oil Derivative Contracts – Canadian Dollar
Term
Volume
(bbls/d)
AverageSwap Price
(Cdn$/bbl)
2016 Weighted Average(1)
43,249
83.01
2017 Weighted Average(2)
13,727
80.62
January – September 2018 Weighted Average
8,310
79.71
 
Notes:
(1) Includes 2,500 bbls/d which can be extended at the option of the counterparty for calendar 2017 at an average swap price of $90.39/bbl.
(2) Includes 4,000 bbls/d which can be extended at the option of the counterparty for calendar 2018 at an average swap price of $86.16/bbl.
Financial WTI Crude Oil Differential Derivative Contracts – Canadian Dollar
Term
Volume
(bbls/d)
Contract
Basis
Fixed Differential ($/bbl)
2016
500
Basis Swap
MSW
(4.50)
Financial AECO Natural Gas Derivative Contracts – Canadian Dollar
Term
Contract
Volume
(GJ/d)
Average Swap Price
(Cdn$/GJ)
2016 Weighted Average
Swap
32,005
3.57
2017 Weighted Average
Swap
16,425
3.55
January – March 2018 Weighted Average
Swap
11,000
3.55

Financial Power Derivative Contracts – Canadian Dollar
Term
Contract
Volume
(MW/h)
Fixed Rate
(Cdn$/MW/h)
2016
Swap
3.0
50.00
2017
Swap
3.0
52.50

Financial Interest Rate Derivative Contracts – Canadian Dollar
Term
Contract
Notional Principal
(Cdn$ millions)
Fixed Annual
Rate (%)
January 2016 – September 2018
Swap
50.0
0.90
January 2016 – September 2018
Swap
50.0
0.87
January 2016 – August 2020
Swap
50.0
1.16
January 2016 – August 2020
Swap
50.0
1.16
January 2016 – August 2020
Swap
100.0
1.15
January 2016 – September 2020
Swap
50.0
1.14
January 2016 – September 2020
Swap
50.0
1.11
 
- 13 -
 
Financial Cross Currency Derivative Contracts
 
Term
Contract
Receive Notional
Principal
(US$ millions)
Fixed Annual Rate
(US%)
Pay Notional Principal
(Cdn$ millions)
Fixed Annual Rate
(Cdn%)
January 2016
Swap
200.0
2.37
262.0
2.64
January 2016
Swap
100.0
2.47
131.2
2.78
January 2016 – February 2016
Swap
100.0
2.39
131.6
2.63
January 2016 – March 2016
Swap
160.0
2.51
216.0
2.62
January 2016 – March 2016
Swap
200.0
2.55
273.8
2.63
January 2016 – March 2016
Swap
200.0
2.55
273.8
2.62
January 2016 – April 2016
Swap
52.0
3.93
50.1
4.84
January 2016 – March 2017
Swap
67.5
5.48
68.9
5.89
January 2016 – April 2018
Swap
31.0
4.58
29.9
5.32
January 2016 – June 2018
Swap
20.0
2.65
20.4
3.52
January 2016 – May 2019
Swap
68.0
3.39
66.7
4.53
January 2016 – March 2020
Swap
155.0
6.03
158.3
6.45
January 2016 – April 2021
Swap
82.0
5.13
79.0
5.83
January 2016 – June 2021
Swap
52.5
3.29
56.3
3.59
January 2016 – May 2022
Swap
170.0
4.00
166.9
5.03
January 2016 – June 2023
Swap
270.0
3.78
274.7
4.32
January 2016 – June 2024
Swap
257.5
3.75
276.4
4.03
January 2016 – April 2025
Swap
230.0
4.08
291.1
4.13
January 2016 – April 2027
Swap
20.0
4.18
25.3
4.25

Financial Foreign Exchange Derivative Contracts
Settlement Date
Contract
Receive Notional
Principal
(US$ millions)
Pay Notional Principal
(Cdn$ millions)
May 22, 2022
Swap
30.0
32.2

In addition to hedging benchmark crude oil and natural gas prices with financial instruments, we have also mitigated crude oil basis risk by delivering a portion of our crude oil production into diversified refinery markets using rail transportation. Crescent Point owns and operates four railcar loading facilities, serving its key producing areas of southeast Saskatchewan, southwest Saskatchewan, central Alberta and Utah. Crude oil volumes loaded at these facilities are sold at the loading facilities and our buyers are responsible for providing railcars and managing transportation logistics from that point until delivery at the refinery gate. By utilizing rail transportation, we have been able to access refining markets that are not pipeline connected to western Canada or Utah, which significantly diversifies our price and market risk. In addition, we have been able to enter into term sales contracts on a portion of the volumes transported by rail, which set the price differential between benchmark WTI prices and our selling price at the loading terminals.
Crescent Point also enters into physical delivery and derivative WTI price differential contracts which manage the spread between US$ WTI and various stream prices. The Corporation manages physical delivery contracts on a month-to-month spot and term contract basis. From January to December 2015, approximately 14,700 bbls/d of oil production was contracted with fixed price differentials off WTI. As of December 31, 2015, approximately 19,000 bbls/d of oil production from January to December 2016, approximately 6,000 bbls/d of oil production from January to December 2017, approximately 5,500 bbls/d of oil production from January to December 2018 and approximately 2,500 bbls/d of oil production from January to December 2019 was contracted with fixed priced differentials off WTI. By locking in the price differential on these volumes, we have been able to reduce our exposure to volatility in crude oil differentials.
We also mitigate risk by having a well-diversified marketing portfolio for oil and natural gas. As a result of our access to rail transportation, we have significantly increased and diversified the number of counterparties with which we transact. Credit risk associated with the Corporation's portfolio of physical crude oil and natural gas sales and with the Corporation's commodity hedging portfolio is managed and mitigated by Crescent Point's Risk Management Committee and is governed by a Board-approved Risk Management and Counterparty Credit Policy that is reviewed by the board of directors on no less than an annual basis. The Policy requires annual credit reviews of all trade counterparties. Credit limits are required to be set for all trade counterparties, which are based on either a fixed dollar amount which is set annually at a minimum or a percentage of the Corporation's portfolio calculated monthly. Crescent Point utilizes a diversified approach in both its physical sales portfolio and its financial hedging portfolio. The physical sales portfolio consists of more than 80 purchasers and its financial hedging portfolio consists of 17 counterparties. The Corporation's portfolio of counterparty exposures is reviewed monthly by the Chief Financial Officer and the Vice President, Marketing and Innovation. Counterparty exposures are also reviewed on a quarterly basis by both the Risk Management Committee and the board of directors.
- 14 -
To further mitigate credit risk associated with its physical sales portfolio, Crescent Point obtains financial assurances such as parental guarantees, letters of credit and third party credit insurance. Including these assurances, approximately 96% of the Corporation's oil and gas sales are with entities considered investment grade.
Our oil and natural gas volumes are sold in the U.S., Alberta, British Columbia, Manitoba and Saskatchewan. Approximately 78% of our oil volumes are sold in Saskatchewan, 13% in the U.S., 6% in Alberta, 3% in Manitoba and less than 1% in British Columbia. Approximately 56% of our natural gas volumes are sold in Saskatchewan, 24% in Alberta, 20% in the U.S. and less than 1% in Manitoba.
Revenue Sources
For 2015, our commodity production mix was approximately 90% oil and NGLs and 10% natural gas.
The following table summarizes our revenue sources by product before hedging and royalties:
For Year Ended
Crude Oil and NGLs
Natural Gas
2015
96%
4%
2014
97%
3%
2013
97%
3%

Competition
We actively compete for reserve acquisitions, exploration leases, licences and concessions and skilled industry personnel with a substantial number of other oil and gas companies, many of which have significantly greater financial resources than we do. Our competitors include major integrated oil and natural gas companies, numerous other independent oil and natural gas entities and individual producers and operators.
Certain of our customers and potential customers are themselves exploring for oil and natural gas, and the results of such exploration efforts could affect our ability to sell or supply oil or gas to these customers in the future. Our ability to successfully bid on and acquire additional property rights, to discover reserves, to participate in drilling opportunities and to identify and enter into commercial arrangements with customers is dependent upon developing and maintaining close working relationships with our industry partners and joint operators, our ability to select and evaluate suitable properties and our ability to consummate transactions in a highly competitive environment.
Seasonal Factors
The production of oil and natural gas is dependent on access to areas where development of reserves is to be conducted. Seasonal weather variations, including freeze-up and break-up, affect access in certain circumstances.
- 15 -
Personnel
As at December 31, 2015, the Corporation had 491 employees and 114 consultants at our head office in Calgary and 81 employees and 11 consultants at our Denver office. In the field, we had 449 field employees and 171 consultants in Canada and 51 field employees and 21 consultants in the US.
Reorganizations
On May 15, 2014, the Corporation closed the CanEra Arrangement for total consideration of approximately $1.1 billion, comprised of 12,928,091 Crescent Point Common Shares, cash consideration of approximately $191.8 million and assumed debt. The acquisition increased the Corporation's Torquay land position in southeast Saskatchewan.
On August 13, 2014, the Corporation closed the acquisition of all issued and outstanding common shares of T. Bird, a private oil and gas company with properties in southeast Saskatchewan and Manitoba. Total consideration was approximately $85.7 million, comprised of 1,482,477 Crescent Point Common Shares, cash consideration of $0.3 million and assumed debt.  The assets offer excellent rates of return and significant exploration potential in multiple horizons.
On June 30, 2015, the Corporation closed the Legacy Arrangement for total consideration of approximately $1.5 billion, comprised of 18,229,428 Crescent Point Common Shares, cash consideration of $19.4 million and assumed debt. The assets increase the Corporation's position in southeast Saskatchewan and includes a significant entry into the emerging Midale resource play.
On August 14, 2015, the Corporation closed the Coral Hill Arrangement, pursuant to which the Corporation acquired all of the remaining issued and outstanding shares of Coral Hill not already owned by the Corporation. Total consideration for the acquisition was $243.8 million, comprised of 4,283,680 Crescent Point Common Shares, assumed debt and the historical cost of Crescent Point's previously held equity investment of $42.0 million. The Coral Hill Arrangement consolidated the Corporation's position in the Swan Hills Beaverhill Lake resource play and provided the Corporation with full operatorship, control over pace of development and an increased position in the core of the play.
Social and Environmental Policies
The Corporation has a voluntary reclamation fund to fund future decommissioning costs and environmental emissions reduction costs. From January 1, 2013 to December 31, 2013, the Corporation allocated $0.70 per boe of production. From January 1, 2014 to March 31, 2014, the Corporation allocated $1.10 per boe of production. From April 1, 2014 to December 31, 2014, the Corporation allocated $1.00 per boe of production and made an additional lump sum contribution of $7.8 million. From April 1, 2015 to December 31, 2015, the Corporation allocated $0.60 per boe of production. Additional contributions can be made at the discretion of management.
STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION
Disclosure of Reserves Data
In accordance with NI 51-101, the reserves data of the Corporation set forth below (the "Reserves Data") is based upon evaluations by GLJ and Sproule with an effective date of December 31, 2015 contained in the consolidated report of GLJ dated March 1, 2016 (the "Crescent Point Reserve Report"). The Crescent Point Reserve Report evaluated, as at December 31, 2015, and summarizes our crude oil, NGL and natural gas reserves. The tables below are a combined summary of our crude oil, NGL and natural gas reserves and the net present value of future net revenue attributable to such reserves as evaluated in the Crescent Point Reserve Report based on Sproule's December 31, 2015 forecast price and cost assumptions. GLJ evaluated approximately 43 percent of the assigned total Proved plus Probable reserves and 32 percent of the total Proved plus Probable value discounted at 10 percent. Sproule evaluated approximately 57 percent of the assigned total Proved plus Probable reserves and 68 percent of the total Proved plus Probable value discounted at 10 percent. Sproule evaluated a majority of our Saskatchewan assets including the Viewfield Bakken and Flat Lake Torquay properties in southeast Saskatchewan as well as the Shaunavon and Saskatchewan Viking properties in southwest Saskatchewan. Sproule evaluated their portion of the reserves using the Sproule forecast price and cost escalation assumptions. GLJ evaluated the Corporation's Alberta, British Columbia and Manitoba assets as well as a portion of the Saskatchewan assets in Canada. GLJ also performed the evaluation of the Corporation's US assets in North Dakota, Montana, Colorado and Utah. These assets were all evaluated using the Sproule forecast price and cost escalation assumptions. GLJ prepared the total Crescent Point Reserve Report by consolidating the GLJ Canadian and US evaluated properties with the Sproule evaluation using the Sproule pricing and cost escalation assumptions. The tables summarize the data contained in the Crescent Point Reserve Report and, as a result, may contain slightly different numbers than such report due to rounding. Also due to rounding, certain columns may not add exactly.
- 16 -
The net present value of future net revenue attributable to our reserves is stated without provision for interest costs, and general and administrative costs, but after providing for estimated royalties, production costs, capital taxes, development costs, other income, future capital expenditures, and well and location abandonment costs for only those entities assigned reserves by GLJ and Sproule. It should not be assumed that the undiscounted or discounted net present value of future net revenue attributable to our reserves estimated by GLJ and Sproule represent the fair market value of those reserves. Other assumptions and qualifications relating to costs, prices for future production and other matters are summarized herein. The recovery and reserve estimates of our crude oil, NGL and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual reserves may be greater than or less than the estimates provided herein.
The Crescent Point Reserve Report is based on certain factual data supplied by us as well as GLJ and Sproule's opinion of reasonable practice in the industry. The extent and character of ownership and all factual data pertaining to our petroleum properties and contracts (except for certain information residing in the public domain) were supplied by the Corporation to GLJ and Sproule, and were accepted without any further investigation. GLJ and Sproule accepted this data as presented and neither title searches nor field inspections were conducted.
Reserves Data – Forecast Prices and Costs
Summary of Oil and Gas Reserves(1)
 
Light and Medium
Crude Oil
Heavy Crude Oil
 
Tight Oil(2)
Natural Gas Liquids
 
Shale Gas(3)
Conventional
Natural Gas
Total
Reserves
Category
Company Gross
(Mbbls)
Company
Net
(Mbbls)
Company
Gross
(Mbbls)
Company
Net
(Mbbls)
Company
Gross
(Mbbls)
Company
Net
(Mbbls)
Company
Gross
(Mbbls)
Company
Net
(Mbbls)
Company Gross
(MMcf)
Company
Net
(MMcf)
Company Gross
(MMcf)
Company
Net
(MMcf)
Company
Gross
(Mboe)
Company
Net
(Mboe)
Proved Developed Producing
                            
Canada
112,359
97,849
22,106
19,645
135,607
124,581
31,563
28,230
68,747
64,662
100,892
92,025
329,908
296,419
United States
1,271
1,037
-
-
24,486
20,042
2,647
2,148
28,350
23,219
13
11
33,132
27,098
Total
113,630
98,885
22,106
19,645
160,093
144,622
34,211
30,377
97,097
87,881
100,904
92,036
363,040
323,517
Proved Developed Non-Producing
                            
Canada
4,856
4,291
282
256
5,278
4,821
1,132
1,010
2,409
2,237
5,312
4,640
12,835
11,525
United States
-
-
-
-
187
158
26
22
254
224
-
-
256
217
Total
4,856
4,291
282
256
5,465
4,979
1,158
1,032
2,663
2,460
5,312
4,640
13,091
11,741
Proved
Undeveloped
                            
Canada
45,641
41,462
2,104
1,738
85,652
80,223
13,988
12,593
43,628
40,498
27,061
25,044
159,166
146,939
United States
-
-
-
-
44,012
35,724
4,752
3,831
47,977
38,991
-
-
56,760
46,054
Total
45,641
41,462
2,104
1,738
129,664
115,947
18,740
16,424
91,605
79,489
27,061
25,044
215,926
192,993
Total Proved
                            
Canada
162,856
143,601
24,492
21,639
226,536
209,625
46,684
41,833
114,784
107,396
133,265
121,708
501,909
454,883
United States
1,271
1,037
-
-
68,685
55,923
7,426
6,001
76,581
62,434
13
11
90,148
73,368
Total
164,127
144,638
24,492
21,639
295,222
265,548
54,109
47,834
191,365
169,831
133,278
121,719
592,056
528,251
Total Probable
                            
Canada
93,782
81,682
8,356
7,145
131,386
119,357
24,136
21,426
60,112
55,784
68,428
62,134
279,083
249,262
United States
5,448
4,476
-
-
46,680
38,120
4,510
3,645
47,165
38,468
104
91
64,516
52,667
Total
99,230
86,158
8,356
7,145
178,066
157,477
28,646
25,070
107,277
94,251
68,532
62,224
343,599
301,929
Total Proved Plus Probable
                            
Canada
256,637
225,283
32,847
28,784
357,923
328,982
70,820
63,259
174,896
163,180
201,693
183,842
780,992
704,144
United States
6,719
5,513
-
-
115,365
94,043
11,936
9,646
123,746
100,902
117
102
154,664
126,036
Total
263,356
230,796
32,847
28,784
473,288
423,025
82,755
72,904
298,642
264,082
201,810
183,944
935,656
830,180
 
- 17 -
Notes:
(1) Numbers may not add due to rounding.
(2) Volumes reported as "Tight Oil" under revised guidelines previously would have been previously reported as "Light & Medium Oil" based on product quality.  These volumes are now considered "Tight Oil" due to reservoir characteristics as well as drilling and completion techniques.
(3) Volumes reported as "Shale Gas" under revised guidelines include gas volumes that have been produced in association with "Tight Oil" or as non-associated shale gas volumes.  These volumes would have previously been reported as "Natural Gas".

Net Present Value of Future Net Revenue of Oil and Gas Reserves(1)
  Before Income Taxes Discounted at
 (%/year)
After Income Taxes Discounted at
(%/year)
Reserves
Category
0%
(MM$)
5%
(MM$)
10%
(MM$)
15%
(MM$)
20%
(MM$)
0%
(MM$)
5%
(MM$)
10%
(MM$)
15%
(MM$)
20%
(MM$)
Proved Developed Producing
                    
Canada
11,712
8,612
6,819
5,655
4,842
11,005
8,201
6,564
5,490
4,730
United States
903
683
548
458
395
859
650
521
436
375
Total
12,615
9,295
7,367
6,113
5,236
11,864
8,851
7,086
5,926
5,106
Proved Developed
Non-Producing
                    
Canada
408
313
249
205
173
279
218
176
146
124
United States
5
4
3
2
2
5
4
3
2
2
Total
414
317
252
207
175
285
222
179
149
126
Proved
Undeveloped
                    
Canada
4,514
2,928
1,954
1,329
909
3,272
2,066
1,326
853
538
United States
1,111
617
346
187
88
956
539
304
163
74
Total
5,626
3,545
2,300
1,515
997
4,228
2,605
1,629
1,016
612
Total Proved
                    
Canada
16,635
11,852
9,022
7,189
5,924
14,556
10,484
8,066
6,489
5,393
United States
2,020
1,305
897
647
485
1,821
1,193
828
601
452
Total
18,654
13,157
9,919
7,836
6,409
16,376
11,677
8,894
7,090
5,844
Total Probable
                    
Canada
11,905
7,025
4,700
3,395
2,580
8,673
5,082
3,371
2,414
1,820
United States
2,067
1,120
692
465
328
1,281
692
433
296
212
Total
13,972
8,144
5,392
3,859
2,908
9,954
5,774
3,804
2,710
2,032
Total Proved Plus Probable
                    
Canada
28,540
18,877
13,722
10,584
8,504
23,229
15,566
11,437
8,903
7,213
United States
4,086
2,424
1,589
1,112
812
3,101
1,885
1,261
897
664
Total
32,626
21,301
15,311
11,695
9,317
26,330
17,452
12,698
9,799
7,876

Note:
(1) Numbers may not add due to rounding.
- 18 -
Additional Information Concerning Future Net Revenue – (Undiscounted)(1)
Reserves Category
Revenue
(MM$)
Royalties(2)
(MM$)
Operating
Costs
(MM$)
Development
Costs
(MM$)
Abandonment and Reclamation
Costs
(MM$)
Future Net
Revenue Before
Income Taxes
(MM$)
Income Tax
(MM$)
Future Net
Revenue After
Income Taxes
(MM$)
Proved
                
Canada
37,350
4,154
12,368
3,341
853
16,635
2,079
14,556
United States
6,606
1,562
1,881
1,064
79
2,020
199
1,821
Total
43,956
5,716
14,249
4,405
932
18,654
2,278
16,376
Proved Plus Probable
                
Canada
60,958
7,037
19,044
5,302
1,036
28,540
5,311
23,229
United States
12,084
2,851
3,349
1,686
113
4,086
985
3,101
Total
73,042
9,888
22,393
6,987
1,149
32,626
6,296
26,330

Notes:
(1) Numbers may not add due to rounding.
(2) Ad valorem and severance taxes payable in the United States and Saskatchewan Capital Resource Surcharge have been included under royalties.
Future Net Revenue by Production Type(6)
 
Future Net Revenue
Before Income Taxes(5)
(Discounted at 10% per year)
Percentage
  
Unit Value
 
(MM$)
(%)
($/boe)
($/Mcfe)
Proved
        
CANADA
        
Light and Medium Crude Oil(1)
2,856
31.7
17.62
2.94
Heavy Crude Oil(1)
416
4.6
19.11
3.19
Tight Oil(3)(7)
5,652
62.6
21.92
3.65
Natural Gas Liquids
-
-
-
-
Shale Gas(4)
-
-
-
-
Conventional Natural Gas(2)
99
1.1
7.43
1.24
Total Canada
9,022
100.0
19.83
3.31
UNITED STATES
        
Light and Medium Crude Oil(1)
17
1.9
16.57
2.76
Heavy Crude Oil(1)
-
-
-
-
Tight Oil(3)(7)
879
98.1
12.16
2.03
Natural Gas Liquids
-
-
-
  
Shale Gas(2)
<1
<0.1
2.44
0.41
Conventional Natural Gas(2)
<1
<0.1
2.47
0.41
Total United States
897
100.0
12.22
2.04
TOTAL
        
Light and Medium Crude Oil(1)
2,874
29.0
17.62
2.94
Heavy Crude Oil(1)
416
4.2
19.11
3.18
Tight Oil(3)(7)
6,531
65.8
19.79
3.30
Natural Gas Liquids
-
-
-
-
Shale Gas(2)(4)
<1
<0.1
2.44
0.41
Conventional Natural Gas(2)
99
1.0
7.43
1.24
Total Proved
9,919
100.0
18.78
3.13

Notes:
(1) Including solution gas and other by-products.
(2) Including by-products, but excluding solution gas.
(3) Including solution gas (categorized as "Shale Gas") and other by-products.
(4) Volumes of Shale Natural Gas has been included in "Tight Oil" as it is solution gas relating to oil production.
(5) Other company revenue and costs not related to a specific production type have been allocated proportionately to production types.  Unit values are based on Company Net Reserves.
(6) Numbers may not add due to rounding.
(7) Volumes reported as "Tight Oil" under revised guidelines previously would have been previously reported as "Light & Medium Oil" based on product quality.  These volumes are now considered "Tight Oil" due to reservoir characteristics as well as drilling and completion techniques.
- 19 -
 
   Future Net Revenue
Before Income Taxes(5)
(Discounted at 10% per year)
  
Percentage
  
Unit Value 
 
(MM$)
(%)
($/boe)
($/Mcfe)
Proved Plus Probable
        
CANADA
        
Light and Medium Crude Oil(1)
4,372
31.9
17.04
2.84
Heavy Crude Oil(1)
510
3.7
17.75
2.96
Tight Oil(3)(7)
8,724
63.6
21.72
3.62
Natural Gas Liquids
-
-
-
-
Shale Gas(4)
-
-
-
-
Conventional Natural Gas(2)
116
0.8
6.77
1.13
Total Canada
13,722
100.0
19.49
3.25
UNITED STATES
        
Light and Medium Crude Oil(1)
42
2.7
7.66
1.28
Heavy Crude Oil(1)
-
-
-
-
Tight Oil(3)(7)
1,547
97.3
12.84
2.14
Natural Gas Liquids
-
-
-
-
Shale Gas(2)
<1
<0.1
3.12
0.52
Conventional Natural Gas(2)
<1
<0.1
-0.69
-0.11
Total United States
1,589
100.0
12.61
2.10
TOTAL
        
Light and Medium Crude Oil(1)
4,415
28.8
16.84
2.81
Heavy Crude Oil(1)
510
3.3
17.75
2.96
Tight Oil(3)(7)
10,270
67.1
19.67
3.28
Natural Gas Liquids
-
-
-
-
Shale Gas(2)(4)
<1
<0.1
3.12
0.52
Conventional Natural Gas(2)
116
0.8
6.76
1.13
Total Proved Plus Probable
15,311
100.0
18.44
3.07
 
Notes:
(1) Including solution gas and other by-products.
(2) Including by-products, but excluding solution gas.
(3) Including solution gas (categorized as "Shale Gas") and other by-products.
(4) Volumes of Shale Natural Gas has been included in "Tight Oil" as it is solution gas relating to oil production.
(5) Other company revenue and costs not related to a specific production type have been allocated proportionately to production types.  Unit values are based on Company Net Reserves.
(6) Numbers may not add due to rounding.
(7) Volumes reported as "Tight Oil" under revised guidelines previously would have been previously reported as "Light & Medium Oil" based on product quality.  These volumes are now considered "Tight Oil" due to reservoir characteristics as well as drilling and completion techniques.
Notes and Definitions
In the tables set forth above in "Disclosure of Reserves Data" and elsewhere in this AIF, the following notes and other definitions are applicable.
Reserve Categories
The determination of oil and gas reserves involves the preparation of estimates that have an inherent degree of associated uncertainty. Categories of Proved and Probable reserves have been established to reflect the level of these uncertainties and to provide an indication of the probability of recovery.
- 20 -
The estimation and classification of reserves requires the application of professional judgment combined with geological and engineering knowledge to assess whether or not specific reserves classification criteria have been satisfied. Knowledge of concepts including uncertainty and risk, probability and statistics, and deterministic and probabilistic estimation methods is required to properly use and apply reserves definitions.
(a) "Reserves" are estimated remaining economic quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on (a) analysis of drilling, geological, geophysical, and engineering data; (b) the use of established technology; and (c) specified economic conditions, which are generally accepted as being reasonable and shall be disclosed. Reserves are classified according to the degree of certainty associated with the estimates.
(b) "Proved" reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.
(c) "Developed Producing" reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.
(d) "Developed Non-Producing" reserves are those reserves that either have not been on production, or have previously been on production, but are shut-in, and the date of resumption of production is unknown.
(e) "Undeveloped" reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (e.g., when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves category (proved, probable, possible) to which they are assigned. In multi-well pools, it may be appropriate to allocate total pool reserves between the developed and undeveloped categories or to sub-divide the developed reserves for the pool between developed producing and developed non-producing. This allocation should be based on the estimator's assessment as to the reserves that will be recovered from specific wells, facilities and completion intervals in the pool and their respective development and production status.
(f) "Probable" reserves are those additional reserves that are less certain to be recovered than Proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated Proved plus Probable reserves.
Levels of Certainty for Reported Reserves
The qualitative certainty levels referred to in the definitions above are applicable to individual reserve entities (which refers to the lowest level at which reserves calculations are performed) and to reported reserves (which refers to the highest level sum of individual entity estimates for which reserves are presented). Reported reserves should target the following levels of certainty under a specific set of economic conditions:
· At least a 90% probability that the quantities actually recovered will equal or exceed the estimated Proved reserves; and
· At least a 50% probability that the quantities actually recovered will equal or exceed the sum of the estimated Proved plus Probable reserves.
A quantitative measure of the certainty levels pertaining to estimates prepared for the various reserves categories is desirable to provide a clearer understanding of the associated risks and uncertainties. However, the majority of reserves estimates will be prepared using deterministic methods that do not provide a mathematically derived quantitative measure of probability. In principle, there should be no difference between estimates prepared using probabilistic or deterministic methods.
- 21 -
Additional Definitions
The following terms, used in the preparation of the Crescent Point Reserve Report and this AIF, have the following meanings:
(a) "associated gas" means the gas cap overlying a crude oil accumulation in a reservoir.
(b) "crude oil" or "oil" means a mixture that consists mainly of pentanes and heavier hydrocarbons, which may contain small amounts of sulphur and other non-hydrocarbons, that exists in the liquid phase in reservoirs and remains liquid at atmospheric pressure and temperature. It does not include liquids obtained from the processing of natural gas.
(c) "development costs" means costs incurred to obtain access to reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas from the reserves. More specifically, development costs, including applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:
(i) gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines and power lines, to the extent necessary in developing the reserves;
(ii) drill and equip development wells, development type stratigraphic test wells and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment and the wellhead assembly;
(iii) acquire, construct and install production facilities such as flow lines, separators, treaters, heaters, manifolds measuring devices and production storage, natural gas cycling and processing plants, and central utility and waste disposal system; and
(iv) provide improved recovery systems.
(d) "development well" means a well drilled inside the established limits of an oil or gas reservoir, or in close proximity to the edge of the reservoir, to the depth of a stratigraphic horizon known to be productive.
(e) "exploration costs" means costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects that may contain oil and gas reserves, including costs of drilling exploratory wells and exploratory type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as "prospecting costs") and after acquiring the property. Exploration costs, which include applicable operating costs of support equipment and facilities and other costs of exploration activities, are:
(i) costs of topographical, geochemical, geological and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews and others conducting those studies (collectively sometimes referred to as "geological and geophysical costs");
(ii) costs of carrying and retaining unproved properties, such as delay rentals, taxes (other than income and capital taxes) on properties, legal costs for title defence, and the maintenance of land and lease records;
(iii) dry hole contributions and bottom hole contributions;
(iv) costs of drilling and equipping exploratory wells; and
(v) costs of drilling exploratory type stratigraphic test wells.
- 22 -
(f) "exploratory well" means a well that is not a development well, a service well or a stratigraphic test well.
(g) "field" means an area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field that are separated vertically by intervening impervious strata or laterally by local geologic barriers, or both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to denote localized geological features, in contrast to broader terms such as "basin", "trend", "province", "play" or "area of interest".
(h) "future prices and costs" means future prices and costs that are:
(i) generally accepted as being a reasonable outlook of the future;
(ii) if, and only to the extent that, there are fixed or presently determinable future prices or costs to which the Corporation is legally bound by a contractual or other obligation to supply a physical product, including those for an extension period of a contract that is likely to be extended, those prices or costs rather than the prices and costs referred to in paragraph (i).
(i) "future income tax expenses" means future income tax expenses estimated (generally, year-by-year):
(i) making appropriate allocations of estimated unclaimed costs and losses carried forward for tax purposes, between oil and gas activities and other business activities;
(ii) without deducting estimated future costs that are not deductible in computing taxable income;
(iii) taking into account estimated tax credits and allowances (for example, royalty tax credits); and
(iv) applying to the future pre-tax net cash flows relating to the Corporation's oil and gas activities the appropriate year end statutory tax rates, taking into account future tax rates already legislated.
(j) "future net revenue" means the estimated net amount to be received with respect to the anticipated development and production of reserves (including synthetic oil, coal bed methane and other non-conventional reserves) estimated using future prices and costs.
(k) "gross" means:
(i) in relation to the Corporation's interest in production or reserves, its "company gross reserves", which are its working interest (operated or non-operated) share before deduction of royalties and without including any royalty interests of the Corporation;
(ii) in relation to wells, the total number of wells in which the Corporation has an interest; and
(iii) in relation to properties, the total area of properties in which the Corporation has an interest.
- 23 -
(l) "natural gas" means a naturally occurring mixture of hydrocarbon gases and other gases.
(m) "natural gas liquids" means those hydrocarbon components that can be recovered from natural gas as liquids including, but not limited to, ethane, propane, butanes, pentanes plus, condensate and small quantities of non-hydrocarbons.
(n) "net" means:
(i) in relation to the Corporation's interest in production or reserves, its working interest (operated or non-operated) share after deduction of royalty obligations, plus its royalty interests in production or reserves;
(ii) in relation to the Corporation's interest in wells, the number of wells obtained by aggregating the Corporation's working interest in each of its gross wells; and
(iii) in relation to the Corporation's interest in a property, the total area in which the Corporation has an interest multiplied by the working interest owned by the Corporation.
(o) "non-associated gas" means an accumulation of natural gas in a reservoir where there is no crude oil.
(p) "operating costs" or "production costs" means costs incurred to operate and maintain wells and related equipment and facilities, including applicable operating costs of support equipment and facilities as well as other costs of operating and maintaining those wells and related equipment and facilities.
(q) "production" means recovering, gathering, treating, field or plant processing (for example, processing gas to extract natural gas liquids) and field storage of oil and gas.
(r) "property" includes:
(i) fee ownership or a lease, concession, agreement, permit, license or other interest representing the right to extract oil or gas subject to such terms as may be imposed by the conveyance of that interest;
(ii) royalty interests, production payments payable in oil or gas, and other non-operated interests in properties operated by others; and
(iii) an agreement with a foreign government or authority under which the Corporation participates in the operation of properties or otherwise serves as "producer" of the underlying reserves (in contrast to being an independent purchaser, broker, dealer or importer).
 
A property does not include supply agreements, or contracts that represent a right to purchase, rather than extract, oil or gas.
 
- 24 -
(s) "property acquisition costs" means costs incurred to acquire a property (directly by purchase or lease, or indirectly by acquiring another corporate entity with an interest in the property), including:
(i) costs of lease bonuses and options to purchase or lease a property;
(ii) the portion of the costs applicable to hydrocarbons when land including rights to hydrocarbons is purchased in fee; and
(iii) brokers' fees, recording and registration fees, legal costs and other costs incurred in acquiring properties.
(t) "proved property" means a property or part of a property to which reserves have been specifically attributed.
(u) "reservoir" means a subsurface rock unit that contains an accumulation of petroleum.
(v) "service well" means a well drilled or completed for the purpose of supporting production in an existing field. Wells in this class are drilled for the following specific purposes: gas injection (natural gas, propane, butane or flue gas), water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for combustion.
(w) "solution gas" means natural gas dissolved in crude oil.
(x) "stratigraphic test well" means a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Ordinarily, such wells are drilled without the intention of being completed for hydrocarbon production. They include wells for the purpose of core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic test wells are classified as (i) "exploratory type" if not drilled into a proved property; or (ii) "development type", if drilled into a proved property. Development type stratigraphic wells are also referred to as "evaluation wells".
(y) "support equipment and facilities" means equipment and facilities used in oil and gas activities, including seismic equipment, drilling equipment, construction and grading equipment, vehicles, repair shops, warehouses, supply points, camps, and division, district or field offices.
(z) "unproved property" means a property or part of a property to which no reserves have been specifically attributed.
(aa) "well abandonment and reclamation costs" means costs of abandoning a well (net of salvage value) and of disconnecting the well from the surface gathering system and reclaiming the site to original conditions. They do not include costs of abandoning the gathering system.
Pricing Assumptions – Forecast Prices and Costs
GLJ and Sproule employed the following pricing, exchange rate and inflation rate assumptions as of December 31, 2015 in estimating our reserves data using forecast prices and costs.
Year
Conventional Natural Gas
Crude Oil
NGLs
      
 
Henry Hub
NYMEX
($US/MMBTU)
AECO/NIT
Spot
($Cdn/MMBTU)
 
WTI at
Cushing
Oklahoma
($US/bbl)
Edmonton
($Cdn/bbl)
Pentanes
Plus
Edmonton
($Cdn/bbl)
Butanes
Edmonton
($Cdn/bbl)
Propane
Edmonton
($Cdn/bbl)
Operating Cost Inflation Rate
(%/yr)
 
Capital Cost Inflation Rate
(%/yr)
Exchange
Rate
($US/$Cdn)
Forecast
                    
2016
2.25
2.25
45.00
55.20
59.10
39.09
9.09
0.0
0.0
0.750
2017
3.00
2.95
60.00
69.00
73.88
51.43
13.64
0.0
4.0
0.800
2018
3.50
3.42
70.00
78.43
83.98
58.46
25.84
1.5
4.0
0.830
2019
4.00
3.91
80.00
89.41
95.73
66.64
35.35
1.5
4.0
0.850
2020
4.25
4.20
81.20
91.71
98.19
68.35
42.30
1.5
1.5
0.850
2021
4.31
4.28
82.42
93.08
99.66
69.38
42.94
1.5
1.5
0.850
2022
4.38
4.35
83.65
94.48
101.16
70.42
43.58
1.5
1.5
0.850
2023
4.44
4.43
84.91
95.90
102.68
71.48
44.24
1.5
1.5
0.850
2024
4.51
4.51
86.18
97.34
104.22
72.55
44.90
1.5
1.5
0.850
2025
4.58
4.59
87.48
98.80
105.78
73.64
45.57
1.5
1.5
0.850
2026
4.65
4.67
88.79
100.28
107.37
74.74
46.26
1.5
1.5
0.850
2027+
+1.5%/yr
+1.5%/yr
+1.5%/yr
+1.5%/yr
+1.5%/yr
+1.5%/yr
+1.5%/yr
1.5
1.5
0.850
 
- 25 -
For the year ended December 31, 2015, the average realized sales prices before hedging were $52.30/bbl for light and medium crude oil, $45.90/bbl for heavy crude oil, $53.31/bbl for tight crude oil, $16.29/bbl for NGLs, $3.04/mcf for shale gas and $2.72/mcf for conventional natural gas.
Reconciliations of Changes in Reserves(1)
The following table sets forth a reconciliation of the Corporation's Company Gross reserves by total Proved, total Probable and total Proved plus Probable reserves as at December 31, 2015 against such reserves as at January 1, 2015 based on forecast price and cost assumptions.
CANADA
  
Light and Medium Crude Oil(2)(4)(5)
(Mbbls)
    
Heavy Crude Oil(4)
(Mbbls)
    
Tight Oil(2)(5)
(Mbbls)
    
Natural Gas Liquids
(Mbbls)
  
Factors
  
Proved
    
Probable
    
Proved
+
Probable
    
Proved
    
Probable
    
Proved
+
Probable
    
Proved
    
Probable
    
Proved
+
Probable
    
Proved
    
Probable
    
Proved
+
Probable
  
January 1, 2015
    
138,535
      
72,617
      
211,151
      
27,616
      
8,097
      
35,713
      
225,691
      
117,735
      
343,426
      
32,165
      
15,973
      
48,137
  
Discoveries
    
-
      
-
      
-
      
-
      
-
      
-
      
-
      
-
      
-
      
-
      
-
      
-
  
Extensions and Improved Recovery
    
7,513
      
4,179
      
11,692
      
-
      
-
      
-
      
15,390
      
12,079
      
27,469
      
1,643
      
1,203
      
2,846
  
Technical Revisions
    
3,584
      
(2,699
)
    
885
      
(870
)
    
340
      
(530
)
    
(1,130
)
    
(7,415
)
    
(8,545
)
    
5,585
      
1,485
      
7,070
  
Acquisitions
    
31,820
      
19,938
      
51,758
      
23
      
8
      
31
      
13,482
      
9,130
      
22,612
      
10,924
      
5,508
      
16,432
  
Dispositions
    
(45
)
    
(14
)
    
(60
)
    
-
      
-
      
-
      
-
      
-
      
-
      
-
      
-
      
-
  
Economic Factors
    
(3,299
)
    
(239
)
    
(3,537
)
    
(160
)
    
(89
)
    
(249
)
    
(651
)
    
(143
)
    
(794
)
    
(242
)
    
(32
)
    
(274
)
Production
    
(15,252
)
    
-
      
(15,252
)
    
(2,117
)
    
-
      
(2,117
)
    
(26,245
)
    
-
      
(26,245
)
    
(3,392
)
    
-
      
(3,392
)
December 31, 2015
    
162,856
      
93,782
      
256,637
      
24,492
      
8,356
      
32,847
      
226,536
      
131,386
      
357,923
      
46,684
      
24,136
      
70,820
  

CANADA
  
Shale Gas(3)(6)
(Natural Gas) (MMcf)
    
Conventional Natural Gas(3)(6)
(Natural Gas) (MMcf)
    
BOE
(Mboe)
  
Factors
  
Proved
    
Probable
    
Proved
+
Probable
    
Proved
    
Probable
    
Proved
+
Probable
    
Proved
    
Probable
    
Proved
+
Probable
  
January 1, 2015
    
97,841
      
44,791
      
142,632
      
70,406
      
45,115
      
115,521
      
452,047
      
229,406
      
681,453
  
Discoveries
    
-
      
-
      
-
      
-
      
-
      
-
      
-
      
-
      
-
  
Extensions and Improved Recovery
    
4,949
      
3,599
      
8,548
      
1,881
      
1,624
      
3,505
      
25,684
      
18,331
      
44,015
  
Technical Revisions
    
(4,150
)
    
(9,973
)
    
(14,122
)
    
21,550
      
1,549
      
23,099
      
10,069
      
(9,693
)
    
376
  
Acquisitions
    
32,191
      
21,765
      
53,955
      
56,500
      
22,399
      
78,898
      
71,031
      
41,945
      
112,975
  
Dispositions
    
-
      
-
      
-
      
-
      
-
      
-
      
(45
)
    
(14
)
    
(60
)
Economic Factors
    
(105
)
    
(70
)
    
(175
)
    
(5,331
)
    
(2,259
)
    
(7,590
)
    
(5,257
)
    
(891
)
    
(6,148
)
Production
    
(15,942
)
    
-
      
(15,942
)
    
(11,739
)
    
-
      
(11,739
)
    
(51,619
)
    
-
      
(51,619
)
December 31, 2015
    
114,784
      
60,112
      
174,896
      
133,265
      
68,428
      
201,693
      
501,909
      
279,083
      
780,992
  
 
- 26 -

UNITED STATES
  
Light and Medium Crude Oil(2)(7)
(Mbbls)
    
Heavy Crude Oil
(Mbbls)
    
Tight Oil(2)(7)
(Mbbls)
    
Natural Gas Liquids
(Mbbls)
  
Factors
  
Proved
    
Probable
    
Proved
+
Probable
    
Proved
    
Probable
    
Proved
+
Probable
    
Proved
    
Probable
    
Proved
+
Probable
    
Proved
    
Probable
    
Proved
+
Probable
  
January 1, 2015
    
204
      
318
      
522
      
-
      
-
      
-
      
61,687
      
40,841
      
102,528
      
4,429
      
2,741
      
7,169
  
Discoveries
    
-
      
-
      
-
      
-
      
-
      
-
      
-
      
-
      
-
      
-
      
-
      
-
  
Extensions and Improved Recovery
    
-
      
-
      
-
      
-
      
-
      
-
      
12,232
      
13,463
      
25,694
      
1,198
      
1,139
      
2,336
  
Technical Revisions
    
(68
)
    
(287
)
    
(355
)
    
-
      
-
      
-
      
5,313
      
(12,049
)
    
(6,736
)
    
2,725
      
503
      
3,228
  
Acquisitions
    
1,469
      
5,417
      
6,886
      
-
      
-
      
-
      
1,043
      
3,161
      
4,205
      
-
      
-
      
-
  
Dispositions
    
-
      
-
      
-
      
-
      
-
      
-
      
(58
)
    
(998
)
    
(1,056
)
    
-
      
-
      
-
  
Economic Factors
    
(39
)
    
-
      
(39
)
    
-
      
-
      
-
      
(5,434
)
    
2,262
      
(3,172
)
    
(386
)
    
129
      
(257
)
Production
    
(295
)
    
-
      
(295
)
    
-
      
-
      
-
      
(6,098
)
    
-
      
(6,098
)
    
(540
)
    
-
      
(540
)
December 31, 2015
    
1,271
      
5,448
      
6,719
      
-
      
-
      
-
      
68,685
      
46,680
      
115,365
      
7,426
      
4,510
      
11,936
  
 
UNITED STATES
  
Shale Gas(3)(8)
(Natural Gas) (MMcf)
    
Conventional Natural Gas(3)(8)
(Natural Gas) (MMcf)
    
BOE
(Mboe)
  
Factors
  
Proved
    
Probable
    
Proved
+
Probable
    
Proved
    
Probable
    
Proved
+
Probable
    
Proved
    
Probable
    
Proved
+
Probable
  
January 1, 2015
    
57,822
      
35,247
      
93,069
      
718
      
498
      
1,216
      
76,077
      
49,856
      
125,933
  
Discoveries
    
-
      
-
      
-
      
-
      
-
      
-
      
-
      
-
      
-
  
Extensions and Improved Recovery
    
9,812
      
10,942
      
20,754
      
-
      
-
      
-
      
15,065
      
16,425
      
31,489
  
Technical Revisions
    
19,640
      
464
      
20,104
      
(629
)
    
(394
)
    
(1,023
)
    
11,138
      
(11,822
)
    
(683
)
Acquisitions
    
-
      
-
      
-
      
-
      
-
      
-
      
2,512
      
8,578
      
11,091
  
Dispositions
    
-
      
-
      
-
      
-
      
-
      
-
      
(58
)
    
(998
)
    
(1,056
)
Economic Factors
    
(3,730
)
    
513
      
(3,217
)
    
-
      
-
      
-
      
(6,481
)
    
2,477
      
(4,004
)
Production
    
(6,964
)
    
-
      
(6,964
)
    
(76
)
    
-
      
(76
)
    
(8,106
)
    
-
      
(8,106
)
December 31, 2015
    
76,581
      
47,165
      
123,746
      
13
      
104
      
117
      
90,148
      
64,516
      
154,664
  


TOTAL
  
Light and Medium Crude Oil(2)(4)(9)(10)
(Mbbls)
    
Heavy Crude Oil(4)(9)
(Mbbls)
    
Tight Oil(2)(10)
(Mbbls)
    
Natural Gas Liquids
(Mbbls)
  
Factors
  
Proved
    
Probable
    
Proved
+
Probable
    
Proved
    
Probable
    
Proved
+
Probable
    
Proved
    
Probable
    
Proved
+
Probable
    
Proved
    
Probable
    
Proved
+
Probable
  
January 1, 2015
    
138,739
      
72,935
      
211,673
      
27,616
      
8,097
      
35,713
      
287,378
      
158,576
      
445,954
      
36,594
      
18,713
      
55,307
  
Discoveries
    
-
      
-
      
-
      
-
      
-
      
-
      
-
      
-
      
-
      
-
      
-
      
-
  
Extensions and Improved Recovery
    
7,513
      
4,179
      
11,692
      
-
      
-
      
-
      
27,622
      
25,542
      
53,164
      
2,840
      
2,341
      
5,182
  
Technical Revisions
    
3,516
      
(2,986
)
    
530
      
(870
)
    
340
      
(530
)
    
4,183
      
(19,465
)
    
(15,282
)
    
8,310
      
1,988
      
10,298
  
Acquisitions
    
33,289
      
25,355
      
58,644
      
23
      
8
      
31
      
14,525
      
12,291
      
26,817
      
10,924
      
5,508
      
16,432
  
Dispositions
    
(45
)
    
(14
)
    
(60
)
    
-
      
-
      
-
      
(58
)
    
(998
)
    
(1,056
)
    
-
      
-
      
-
  
Economic Factors
    
(3,338
)
    
(239
)
    
(3,576
)
    
(160
)
    
(89
)
    
(249
)
    
(6,085
)
    
2,119
      
(3,966
)
    
(628
)
    
97
      
(531
)
Production
    
(15,546
)
    
-
      
(15,546
)
    
(2,117
)
    
-
      
(2,117
)
    
(32,343
)
    
-
      
(32,343
)
    
(3,932
)
    
-
      
(3,932
)
December 31, 2015
    
164,127
      
99,230
      
263,356
      
24,492
      
8,356
      
32,847
      
295,222
      
178,066
      
473,288
      
54,109
      
28,646
      
82,755
  

TOTAL
  
Shale Gas(3)(11)
(Natural Gas) (MMcf)
    
Conventional Natural Gas(3)(11)
(Natural Gas) (MMcf)
    
BOE
(Mboe)
  
Factors
  
Proved
    
Probable
    
Proved
+
Probable
    
Proved
    
Probable
    
Proved
+
Probable
    
Proved
    
Probable
    
Proved
+
Probable
  
January 1, 2015
    
155,663
      
80,038
      
235,701
      
71,124
      
45,613
      
116,737
      
528,124
      
279,262
      
807,386
  
Discoveries
    
-
      
-
      
-
      
-
      
-
      
-
      
-
      
-
      
-
  
Extensions and Improved Recovery
    
14,761
      
14,541
      
29,302
      
1,881
      
1,624
      
3,505
      
40,749
      
34,756
      
75,505
  
Technical Revisions
    
15,490
      
(9,509
)
    
5,982
      
20,921
      
1,156
      
22,076
      
21,208
      
(21,515
)
    
(307
)
Acquisitions
    
32,191
      
21,765
      
53,955
      
56,500
      
22,399
      
78,898
      
73,543
      
50,523
      
124,066
  
Dispositions
    
-
      
-
      
-
      
-
      
-
      
-
      
(103
)
    
(1,012
)
    
(1,116
)
Economic Factors
    
(3,835
)
    
443
      
(3,392
)
    
(5,331
)
    
(2,259
)
    
(7,590
)
    
(11,738
)
    
1,586
      
(10,152
)
Production
    
(22,905
)
    
-
      
(22,905
)
    
(11,816
)
    
-
      
(11,816
)
    
(59,725
)
    
-
      
(59,725
)
December 31, 2015
    
191,365
      
107,277
      
298,642
      
133,278
      
68,532
      
201,810
      
592,056
      
343,599
      
935,656
  
 
 
Notes:
(1) Numbers may not add due to rounding.
(2) Volumes reported as "Tight Oil" under revised guidelines would have been previously reported as "Light & Medium Oil" based on product quality.  These volumes are now considered "Tight Oil" due to reservoir characteristics as well as drilling and completion techniques.
(3) Volumes reported as "Shale Gas" under revised guidelines relate to gas volumes that have been produced in association with "Tight Oil" or as non-associated shale gas volumes.  These volumes would have been previously reported as "Associated and Non-Associated Gas".
(4) Opening balance for Light and Medium Crude Oil represents the reported December 31, 2014 closing less Proved 26,602 Mbbls; Probable 7,358 Mbbls; and Proved plus Probable 33,960 Mbbls transferred to the respective reserve categories in Heavy Crude Oil as a result of a clarification on oil produced in southwest Saskatchewan.  The quoted values included in the opening balance of Heavy Crude Oil reflect these respective inclusions.
(5) Opening balance for Light and Medium Crude Oil represents the reported December 31, 2014 closing less Proved 225,691 Mbbls; Probable 117,735 Mbbls; and Proved plus Probable 343,426 Mbbls transferred to the respective reserve categories in Tight Oil as a result of revised reporting requirements under NI 51-101 for that product.  These volumes are now considered Tight Oil due to reservoir characteristics as well as drilling and completion techniques.  The quoted values included in the opening balance of Tight Oil reflect these respective inclusions.
(6) Opening balance for Associated and Non-Associated Gas represents the reported December 31, 2014 closing less Proved 97,841 MMcf; Probable 44,791 MMcf; and Proved plus Probable 142,632 MMcf transferred to the respective reserve categories in Shale Gas as a result of revised reporting requirements under NI 51-101 for that product.  These volumes are now considered Shale Gas due to their association with the production of Tight Oil.  The quoted values included in the opening balance of Shale Gas reflect these respective inclusions.
(7) Opening balance for Light and Medium Crude Oil represents the reported December 31, 2014 closing less Proved 61,687 Mbbls; Probable 40,841 Mbbls; and Proved plus Probable 102,528 Mbbls transferred to the respective reserve categories in Tight Oil as a result of revised reporting requirements under NI 51-101 for that product.  These volumes are now considered Tight Oil due to reservoir characteristics as well as drilling and completion techniques.  The quoted values included in the opening balance of Tight Oil reflect these respective inclusions.
(8) Opening balance for Associated and Non-Associated Gas represents the reported December 31, 2014 closing less Proved 57,822 MMcf; Probable 35,247 MMcf; and Proved plus Probable 93,069 MMcf transferred to the respective reserve categories in Shale Gas as a result of revised reporting requirements under NI 51-101 for that product. These volumes are now considered Shale Gas due to their association with the production of Tight Oil, or inclusion as non-associated shale gas volumes.  The quoted values included in the opening balance of Shale Gas reflect these respective inclusions.
 
- 27 -
 
(9) Opening balance for Light and Medium Crude Oil represents the reported December 31, 2014 closing less Proved 26,602 Mbbls; Probable 7,358 Mbbls; and Proved plus Probable 33,960 Mbbls transferred to the respective reserve categories in Heavy Crude Oil as a result of a clarification on oil produced in southwest Saskatchewan.  The quoted values included in the opening balance of Heavy Crude Oil reflect these respective inclusions.
(10) Opening balance for Light and Medium Crude Oil represents the reported December 31, 2014 closing less Proved 287,378 Mbbls; Probable 158,576 Mbbls; and Proved plus Probable 445,954 Mbbls transferred to the respective reserve categories in Tight Oil as a result of revised reporting requirements under NI 51-101 for that product.  These volumes are now considered Tight Oil due to reservoir characteristics as well as drilling and completion techniques.  The quoted values included in the opening balance of Tight Oil reflect these respective inclusions.
(11) Opening balance for Associated and Non-Associated Gas represents the reported December 31, 2014 closing less Proved 155,663 MMcf; Probable 80,038 MMcf; and Proved plus Probable 235,701 MMcf transferred to the respective reserve categories in Shale Gas as a result of revised reporting requirements under NI 51-101 for that product. These volumes are now considered Shale Gas due to their association with the production of Tight Oil, or inclusion as non-associated shale gas volumes.  The quoted values included in the opening balance of Shale Gas reflect these respective inclusions.
Undeveloped Reserves
The following discussion generally describes the basis on which we attribute Proved and Probable undeveloped reserves. Our near-term plans for developing our undeveloped reserves are described in the section "Major Oil and Gas Properties".
Proved Undeveloped Reserves
Proved undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure is required to render them capable of production. In addition, such reserves may relate to planned infill drilling locations. The majority of these reserves are planned to be on stream within a three year timeframe. The following table provides the timing of the initial reserve assignments for the Corporation's gross Proved undeveloped reserves.
The Corporation has extensive opportunities that are developed based on a disciplined set of criteria including, but not limited to time to payout, rate of return, maturity of land tenure, reserve booking opportunities, proximity to transportation and marketing, as well as anticipated production rates. With this extensive portfolio of opportunities, it would be unrealistic both from a cash flow as well as ability to execute basis to complete our entire portfolio of booked opportunities within two years. No material deferrals of development opportunities have been proposed beyond the Corporation living within its cash flow.
Timing of Initial Proved Undeveloped Reserve Assignment
   
Light & Medium
Crude Oil (Mbbl)
    
Heavy Crude Oil
(Mbbl)
    
Tight Oil
(Mbbl)
    
Natural Gas Liquids
(Mbbl)
    
Shale Gas
(MMcf)
    
Conventional
Natural Gas (MMcf)
    
Oil Equivalent
(Mboe)
  
   
First
Attributed
(1)
    
Total at
 Year-End
    
First
 Attributed
(1)
    
Total at
 Year-End
    
First
 Attributed
(1)
    
Total at
 Year-End
    
First
 Attributed
(1)
    
Total at
Year-End
    
First
 Attributed
(1)
    
Total at
Year-End
    
First
 Attributed
(1)
    
Total at
 Year-End
    
First
 Attributed
(1)
    
Total at
 Year-End
  
2013
    
37,482
      
157,511
      
39
      
146
      
-
      
-
      
1,481
      
8,867
      
-
      
-
      
25,491
      
88,495
      
43,250
      
181,272
  
2014
    
31,264
      
175,824
      
-
      
132
      
-
      
-
      
5,406
      
16,343
      
-
      
-
      
14,771
      
95,273
      
39,133
      
208,178
  
2015
    
8,793
      
45,641
      
-
      
2,104
      
11,854
      
129,664
      
2,590
      
18,740
      
13,891
      
91,605
      
7,949
      
27,061
      
26,877
      
215,926
  

Note:
(1) "First attributed" refers to reserves first attributed at year-end to corresponding fiscal year.  Prior year Tight Oil and Shale Gas values are included with light and medium crude oil and conventional natural gas, respectively.
Probable Undeveloped Reserves
Probable undeveloped reserves are generally those reserves tested or indicated by analogy to be productive and lands contiguous to production. The majority of these reserves are planned to be on stream within a five year timeframe. The following table provides the timing of the initial reserve assignments for the Corporation's Probable undeveloped gross reserves.
Other than for normal budgetary constraints, the Corporation has no plans to defer development of probable undeveloped reserves.  In the reserve evaluation, development of these reserves is balanced across a five-year time-frame to closely match the aggregate internal development schedule and represent a practicable development program.
- 28 -
Timing of Initial Probable Undeveloped Reserves Assignment
   
Light & Medium
Crude Oil (Mbbl)
    
Heavy Crude Oil
(Mbbl)
    
Tight Oil
(Mbbl)
    
Natural Gas Liquids
(Mbbl)
    
Shale Gas
(MMcf)
    
Conventional
Natural Gas (MMcf)
    
Oil Equivalent
(Mboe)
  
   
First
Attributed
(1)
    
Total at
 Year-End
    
First
 Attributed
(1)
    
Total at
 Year-End
    
First
 Attributed
(1)
    
Total at
 Year-End
    
First
 Attributed
(1)
    
Total at
Year-End
    
First
 Attributed
(1)
    
Total at
Year-End
    
First
 Attributed
(1)
    
Total at
 Year-End
    
First
 Attributed
(1)
    
Total at
 Year-End
  
2013
    
42,447
      
118,895
      
8
      
214
      
-
      
-
      
1,482
      
4,985
      
-
      
-
      
23,412
      
64,916
      
47,839
      
134,913
  
2014
    
41,979
      
135,421
      
-
      
267
      
-
      
-
      
5,198
      
9,602
      
-
      
-
      
18,753
      
73,398
      
50,303
      
157,522
  
2015
    
14,585
      
58,775
      
-
      
1,803
      
16,008
      
106,175
      
2,906
      
14,524
      
13,363
      
64,188